This invention relates to the materials used for and process for both the removal of sulfur compounds from a gaseous stream and for the water gas shift reaction. More specifically, the invention relates to the use of a sulfur absorbent and a water gas shift catalyst used as a physical mixture or in separated bed configurations to provide for simultaneous desulfurization and complete water gas shift at temperatures of about 450° C.
The gaseous stream may originate from any partial oxidation or gasification process of any carbon containing feedstock. The gaseous stream may be a fuel gas originating from an IGCC (Integrated Gasification Combined Cycle) coal gasification plant, it may be a flue gas from a fluid catalytic cracking unit (FCC), and it may be a synthesis gas (syngas) from steam reforming of natural gas, certain gasification reactions or from gasification of coal. Synthesis gas is the name generally given to a gaseous mixture principally comprising carbon monoxide and hydrogen, but also possibly containing carbon dioxide and minor amounts of methane and nitrogen. It is used, or is potentially useful, as feedstock in a variety of large-scale chemical processes, for example: the production of methanol, the production of gasoline boiling range hydrocarbons by the Fischer-Tropsch process and the production of ammonia. Processes for the production of synthesis gas are well known and generally comprise steam reforming, auto-thermal reforming, non-catalytic partial oxidation of light hydrocarbons or non-catalytic partial oxidation of any hydrocarbons. In such a process, molecules of hydrocarbons are broken down to produce a hydrogen-rich gas stream.
IGCC technology produces air emissions that are already considerably lower than required by current U.S. Clean Air standards. Significant reductions in sulfur dioxide (SO2), nitrogen oxides (NOx) and carbon monoxide (CO) are possible through use of IGCC plants, making them more advantageous in this respect than conventional coal power plants. Carbon dioxide (CO2), which is considered a major source of global warming, can be captured more economically with IGCC than with conventional technologies. The CO2 could be sequestered or sold in part as a by-product. Overall efficiency is approximately 40 to 45 percent of the energy value of coal converted to electricity. In comparison, conventional coal plants are approximately 30 to 35 percent efficient. Water requirements are typically about 50 percent less for IGCC applications than for conventional coal generation. Marketable by-products from the IGCC process can be sold, such as sulfur. However, IGCC facilities are more expensive to build than conventional coal plants. Only recently have suppliers begun to emerge that can offer comprehensive, integrated designs with packaged systems and compatible equipment. Due to the industry's limited experience with the technology, truly accurate cost estimates for construction and operating costs are not yet available for use in planning future facilities.
IGCC technology requires more frequent maintenance with longer maintenance outages, requiring that power be purchased from other resources when the IGCC plant is unavailable. Neither of the U.S.-based IGCC projects has used Powder River Basin, or western, coal, which is the type used most frequently in the Midwest. The industry is encouraging suppliers to offer performance contracts for next-generation IGCC plants, but for now, the risk of reduced reliability and availability add significant cost to the project's financing.
Only a few IGCC projects have been built world-wide despite the potential benefits of the technology. Among the improvements that are sought are methods of cleaning up the hot coal derived gases produced in an IGCC project. In prior art systems, wet scrubbing techniques have been used to clean up the gases. Unfortunately, these systems require first cooling of the gas and then a subsequent reheating step.
Regardless of the carbon source and gasification process, a fuel gas has to be substantially cleaned before being either burned in a gas turbine or used for chemical synthesis, e.g., methanol, ammonia, urea production, or Fischer-Tropsch synthesis. Cleanup techniques require removal of solid particulates, sulfur-containing gases, i.e., H2S and COS as well as all trace contaminants resulting from the gasification of coal. These contaminants include ammonia, hydrogen cyanide, chlorides, alkali metals, metal carbonyls, Hg, As, Se. Ideally, the clean-up of the fuel gas would be done at the highest temperature possible that the fuel gas distribution system can be designed for since this would avoid the loss of sensible heat due to the cooling and subsequent reheating associated with wet scrubbing techniques used in prior art processes. If the fuel gas is cleaned with the conventional cold gas cleanup, the penalties in both thermal and overall process efficiencies will be larger for air-blown gasifiers compared to O2-blown gasifiers, because the former produces over twice the volume of fuel gas produced by the latter. But nevertheless, both air- and O2-blown gasifiers would benefit from the successful development of warm or hot-gas cleanup techniques.
Hot particulate removal systems have been successfully demonstrated commercially, but the cleanup of undesired gases still needs to be developed. All large scale warm desulfurization demonstration units have failed mostly due to inappropriate sulfur-scavenger materials. The warm gas desulfurization demonstration units at the Piñon Pine Air-Blown IGCC and at the Tampa Electric Polk Power station used Zn-based S-scavenger materials. The Piñon Pine Air-Blown and Hot Gas Cleanup IGCC using a KRW air-blown pressurized fluidized-bed coal gasification system with Southern Utah bituminous coal containing 0.5-0.9% sulfur (design coal) and Eastern bituminous coal containing 2-3% sulfur (planned test). The purpose was to demonstrate air-blown, pressurized, fluidized-bed IGCC technology incorporating hot gas cleanup (HGCU); to evaluate a low-Btu gas combustion turbine; and to assess long-term reliability, availability, maintainability, and environmental performance at a scale sufficient to determine commercial potential. Steady state operation was not reached in the course of the 42 months demo operation and the Zn-based S-scavenger material failed since it did not hold up physically in the entrained bed reactor. Zn was lost during the 538° C. reaction via volatilization. The second large scale hot gas desulfurization demo unit at Tampa Electric Polk Power station intended to clean 10% of the fuel gas by a hot-gas cleanup system developed by GE Environmental Services, Inc. The hot gas desulfurization unit was an intermittently moving bed of Zn oxide based sorbent that operated at 482° C. The demonstration again failed due to very high attrition loss (which made operation with that particular sorbent far from cost effective) and due to significant reactivity loss because of Zn sulfate formation and Zn volatilization. (References: The Piñon Pine IGCC Project, U.S. DOE and Piñon Pine Power Project Reports, December 1996; January 2001 (DE-FC-21-92MC29309); The Tampa Electric IGCC Project, U.S. DOE and Tampa Electric Reports, October 1996; July 2000; August 2002 (DE-FC-21-91MC27363).
In addition, with the current state of development of hot gas cleanup systems, other contaminants besides sulfur compounds and solid particulates can not be removed at equally high temperatures. A further consideration is that due to the concern about global warming, there will be regulatory requirements to remove carbon dioxide from gasification plants. This will mean that all IGCCs will need to be equipped with at least one CO-shift reactor, requiring thus cooling the fuel gas to temperatures adequate for the water gas shift catalytic reaction. In view of these CO2 regulations, the trend in the gasification industry is towards the use of direct water quench gasifiers. The quench mode design significantly reduces the capital cost of syngas cooling, while heat integration maintains good overall thermal efficiency. The quench mode is advantageous for the water gas shift reaction as the raw syngas becomes saturated with steam generated by evaporation of a portion of the quench water. An entrained-flow slurry-fed gasification with direct water quenching is the preferred and commonly used option of GE Energy, and recently, Shell, Lurgi and Siemens also offer the water quenching cooling method. In addition to efficiently cooling the raw syngas and recovering part of the sensible heat, significant decontamination takes place in the quenching step. Solid particulates, alkali metals, non-volatile metals, chlorides, the bulk of metal carbonyls and part of ammonia are all removed in the water quenching step. The contaminants left in the raw syngas after the water quenching step include about 50-100 ppmv ammonia, 1 to 4 ppmv Ni and Fe carbonyls, about 50-100 ppmv HCN, Hg, As, and sulfur-containing gases, i.e., H2S and COS. All these contaminants must be removed before the syngas is either burned in a gas turbine or used for chemical synthesis.